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Brine Chemistry Effects in Waterflood and CO2 Injection in Carbonate Reservoirs

[+] Author Affiliations
Hemanta K. Sarma, Yi Zhang

The Petroleum Institute, Abu Dhabi, UAE

Paper No. OMAE2014-23247, pp. V005T11A003; 15 pages
doi:10.1115/OMAE2014-23247
From:
  • ASME 2014 33rd International Conference on Ocean, Offshore and Arctic Engineering
  • Volume 5: Materials Technology; Petroleum Technology
  • San Francisco, California, USA, June 8–13, 2014
  • Conference Sponsors: Ocean, Offshore and Arctic Engineering Division
  • ISBN: 978-0-7918-4545-5
  • Copyright © 2014 by ASME

abstract

It has been reported that the waterflood performance in carbonate reservoirs could be significantly ameliorated by tuning the injected brine salinity and ionic composition. Also, it is noted that the brine salinity affects the CO2 injection process. This study looked into such possible effects of brine chemistry on waterflood and CO2 injection for typical UAE carbonate reservoir conditions of high temperature and pressure (T = 120°C and P = 20.68MPa).

Effects on waterflood performance were investigated experimentally by a series of flooding tests at temperatures of 70°C and 120°C. In addition, an imbibition test was conducted at 70°C, followed by wettability monitoring tests at 90°C to investigate the impact of brine salinity variations and ionic compositions on waterflood performance.

The impact of brine salinity on CO2-brine system properties including CO2 solubility in brine, interfacial tension between CO2 and CO2-saturated brine, and density and viscosity of CO2-saturated brine were evaluated through correlation-based studies in conjunction with some experimental data. A mathematical pore-scale model was developed to assess the brine salinity effect on water-isolated oil recovery by CO2 diffusion through water barrier. This study led to the following findings:

(1) Incremental oil recovery could be obtained by either reducing salinity or increasing sulfate concentration of the tertiary injected brine at both 70°C and 120°C. However, the incremental recovery was more remarkable at the higher temperature of 120°C.

(2) At 70°C, lowering the water salinity is more effective than raising the sulfate concentration in injected water in terms of incremental oil recovery. It also exhibited a similar potential for increased oil recovery at 120°C.

(3) Wettability monitoring tests showed that water-wetness of carbonate rock studied could be increased by either reducing the water salinity or increasing sulfate concentration of the surrounding water. This is consistent with the imbibition test, in which wettability alteration towards more water-wetness by low salinity water was noted.

(4) Under typical UAE reservoir conditions, reducing the brine salinity could significantly enhance CO2 dissolution in brine, consequently inducing significant variation to the CO2-brine system properties. This would undoubtedly impact CO2 injection performance.

(5) Under typical UAE reservoir conditions, the capacity and rate of CO2 diffusion through water barrier to oil phase could be significantly reinforced by lowering the brine salinity of the water barrier.

Copyright © 2014 by ASME

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